Two-step artificial lift system and method

ABSTRACT

A two-step artificial lift system and method is proposed which provides for lifting of reservoir fluids without fluid injection using a first step system and lifting of reservoir fluids with fluid injection using a second step system. The second step system reuses the components of the first step system. The system and method aids in lifting reservoir fluids from vertical, deviated, and horizontal wellbores.

1. FIELD OF THE DISCLOSURE

The present disclosure relates to artificial lift production systems andmethods deployed in oil and gas wells, and more particularly relates tosystems and methods in vertical wells with long perforated intervals,deep reservoirs, high gas to liquid ratio reservoirs, and in deviatedwellbores such as horizontal and slanted wells.

2. DESCRIPTION OF THE RELATED ART

Many oil and gas wells experience liquid loading at some point duringtheir productive lives due to the reservoir's inability to providesufficient energy to carry liquids through the wellbore to the surface.The liquids that accumulate in the wellbore may cause the well to ceaseflowing or to flow at a reduced rate. To increase or re-establishproduction, operators may place the well on artificial lift, which isdefined as a method of removing wellbore liquids to the surface byartificially applying some form of energy into the wellbore.

Currently, the most common artificial lift systems in the oil and gasindustry are down-hole pumping systems and gas lift systems. In general,in order for reservoir liquids to be lifted, the liquid level in thewellbore must be above these artificial lift systems. The most popularform of down-hole pump is the sucker rod pump, which is a positivedisplacement pump consisting of a dual ball and seat assembly and aplunger inside a pump barrel. Generally, the plunger is connected by astring of rods contained inside a production tubular string. A surfaceapparatus provides the reciprocating motion to the rods which in turnprovides the reciprocal motion to stroke the pump. As the pump strokes,fluids above the pump are gravity fed into the plunger and barrel andare pumped up the production tubular and out of the wellbore to surfacefacilities. Other popular forms of artificial lift include progressivecavity pumps (PCP), hydraulic pumps (such as piston pumps and jetpumps), and centrifugal pumps such electric submersible pumps (ESPs). Agas lift system operates by injecting pressured gas below the liquidlevel in the wellbore to commingle and reduce the density of thereservoir liquids and raise them to the surface.

In general, the greater the bottom-hole pressure in a depletion drivereservoir, the greater the remaining hydrocarbon reserves present inthat reservoir; therefore, the economical lowering of the bottom-holepressure by artificial lift is crucial in ensuring an efficient recoveryof a well's reserves. If a well is allowed to have a liquid column abovethe reservoir, the back pressure that the liquid column exerts on thereservoir will reduce the production from the reservoir and may evencause the well to cease flowing since flow into the wellbore isdetermined by the differential pressure from the reservoir to thesurface facilities. If this back pressure prevents the reservoir fromlifting liquids to the artificial lift equipment, the well will ceaseproducing liquids, since conventional artificial lift equipment andmethods are not designed to lift liquids that exist below the down-holeequipment. Therefore, it is beneficial for operators to lower theartificial lift equipment to the deeper regions of the wellbore tominimize the reserves that will be left behind.

U.S. Pat. No. 8,985,221, herein incorporated by reference, includes adual stage, dual concentric tubing, artificial lift method utilizing afluid displacement device in conjunction with gas injection in the samewellbore. This artificial lift system operates by using injection gas toraise the liquids that exist below the pump to above the pump. Thewellbore contains a first tubing string that begins at the surface andis connected to a bi-flow connector, a bushing, a perforated sub, and apacker in the wellbore. The first tubing string extends below thepacker. A second tubing string is connected to the bottom of the bushingand extends inside the first tubing string below the packer. A thirdtubing string begins at the surface and extends inside the first tubingstring and connects to the bi-flow connector. A fluid displacementdevice is installed inside the third tubing string.

U.S. Pat. No. 8,985,221 also shows a method that includes injection ofgas into the well from the surface so that the injected gas travels downthe annulus between the first and third tubing string. The injection gaspasses through the body of the bi-flow connector (lengthwise) and entersand exits the second tubing string and commingles with and liftsreservoir fluids up the annulus between the first and second tubingstrings. These commingled fluids exit into the casing annulus throughthe perforated sub. Liquids are prevented from falling back down thewellbore by the packer. Gas separates from the commingled fluids andtravels to the surface while the liquids fall and enter through the sidebody (width) of the bi-flow connector and enter the fluid displacementdevice where they are pumped upwards through the third tubing string tothe surface. Since gas injection is required, the third tubing string isneeded to provide an annular pathway for the injection gas in thewellbore. An additional wellhead is also required at the surface tosupport the third tubing string and the gas injection requires apressurized gas source, gas flowline, and a gas meter.

A shortcoming of the prior art is that the requirement of a third tubingstring concentric with the first tubing string during all operationslimits the liquid production rates for smaller casing sizes and deeperpump setting depths. Generally, higher liquid production rates anddeeper pump setting depths require larger diameter third tubing stringsto house larger diameter fluid displacement devices and associatedequipment, such as sucker rods. Since the third tubing string has alarger diameter, the first tubing string must also have a largerdiameter to house the larger third tubing string. A larger diameterfirst tubing string necessarily reduces the cross-sectional area of thecasing annulus, which is the pathway for the commingled reservoir andinjection gas to reach the surface. For example, a popular casing sizefor a wellbore is 5.5-inch diameter that weighs 17 lbs. per foot. Ahigher capacity down-hole pump would require a first tubing string witha 3.5-inch diameter and an inner third tubing string with a 2.375-inchdiameter. A lower capacity down-hole pump would require a first tubingstring with a 2.875-inch diameter and a third tubing string with a1.9-inch diameter. The cross-sectional area of the annulus between thecasing and the first tubing string for the higher capacity scenario is35% less at the tube portion of the first tubing string and 64% less atthe connections of the first tubing string versus the lower capacityscenario. This smaller cross-sectional area results in a highercommingled gas velocity that will lift the reservoir liquids up thecasing annulus, which is undesirable because the cross-sectional areaand length of the pathway is too great and the annular shape is notconducive for efficiently lifting the fluids to the surface. Instead,gas will break out of the liquid causing liquid fall back and willresult in liquid slugs being suspended in the annulus. These liquidslugs cannot enter the displacement pump while suspended, will exertback pressure on the reservoir, and will raise the gas injectionpressure, thereby reducing the inflow from the reservoir. Additionally,gas pockets will begin to surround the down-hole pump, starving the pumpfor liquids and causing pump inefficiencies and shut downs. Thus, theproduction rate is further reduced and the purpose of installing ahigher capacity down-hole pump is defeated. Gas injection during theseconditions will lower the production rate further since it will worsenthe gas and liquid slugging in the casing annulus.

Another shortcoming in the prior art is many wells may not require gasinjection, especially when there is sufficient reservoir energy forliquids to flow naturally up the annulus between the first and secondtubing strings. Therefore, the gas injection and the associatedequipment and the third tubing string and the associated wellhead are anadditional expense both for installation and operation and may reduceoperational effectiveness.

Another shortcoming of the prior art is the use of the annulus betweenthe first and second tubing strings as a velocity string flow path forlifted reservoir liquids where the annular cross-sectional area isgreater than the cross-sectional area inside the second tubing string,resulting in lower velocity and higher density in the lifted fluids.

Another shortcoming of the prior art is that the separation of solidsfrom the reservoir fluids depends solely on gravity. Gravity is notalways sufficient for complete separation, and solids entrained in thereservoir fluids may enter the fluid displacement device when priorseparation is incomplete. Solids in a fluid displacement device caninterfere with operations and cause wear and damage to the displacementdevice.

Another shortcoming in the prior art is that the dual stage artificiallift system is only shown using gas as the injected fluid to providelift operations.

There is a need for an artificial lift system and method to provide anoptimized artificial lift system and method for wells that havesufficient reservoir energy to flow naturally up to fluid displacementdevice without a third tubing string, associated wellhead, gas injectionand the associated pressured gas source, gas flowline, and gas meter,while also providing the ability to install gas injection for the samewell later in life when the well's reservoir energy declinessufficiently to warrant additional gas injection to aid in liftingreservoir liquids. There is also a need to perform the gas injectionwithout having to do a major workover to remove the existing wellboreequipment.

Additionally, there is a need for a dual artificial lift system andmethod that provides for higher production rates should the well notneed gas or fluid injection by allowing a larger fluid displacementdevice and/or the associated equipment.

There is also a need for an artificial lift system and method thatallows a velocity string only installation to be converted to a dualartificial lift system without having to remove the entire tubularassembly from the well which will have less workover risk, save time,and cost less for installation.

Additionally, there is a need for a more efficient solid separationdesign that utilizes the momentum of the solids to aid in solidsseparation.

Yet another need exists for a dual stage artificial lift system that canuse power fluid for a hydraulic pump instead of gas lift for wells thatdo not have a sufficient supply of gas for gas lift operations.

Additionally, there is a need for a more efficient velocity string liftdesign that uses the inside of the second tubing string to naturallylift liquids from the reservoir to increase the velocity and reduce thedensity of the lifted fluids.

There is also a need for a more efficient velocity string lift designthat, when reservoir pressure requires gas injection based artificiallift, uses the annulus between the first and second tubing strings forgas injection and utilize the inside of the second tubing string as avelocity string pathway for the lifted reservoir liquids to increasevelocity and reduce density of the lifted liquids.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure is related to an apparatus and systemfor providing artificial lift in oil and gas wells. Specifically, thepresent disclosure is related to providing artificial lift in vertical,directional, and horizontal portions of a wellbore.

One embodiment according to the present disclosure includes anartificial lift system for use in a wellbore extending from a surface toa subterranean reservoir containing reservoir fluids, the systemcomprising: a casing disposed in the wellbore; a first tubular stringdisposed in the casing; an upper bi-flow connector disposed in the firsttubular string, a lower bi-flow connector disposed in the first tubularstring below the upper bi-flow connector; a second tubular stringdisposed below the lower bi-flow connector and sealingly engaging thelower bi-flow connector, wherein the lower bi-flow connector allows flowbetween the second tubular string and the annulus between the casing andthe first tubular string; a first fluid displacement device disposed inthe first tubular above the upper bi-flow connector, wherein the upperbi-flow connector allows flow between an annulus formed by the casingand the first tubular string and the fluid displacement device; and afirst seating nipple disposed in the first tubular string above theupper bi-flow connector, wherein the fluid displacement device isreleaseably connected to the first seating nipple.

Another embodiment according to the present disclosure includes a methodof modifying an artificial lift system described above by: removing thefirst fluid displacement pump from the releaseably connected firstsealing nipple; inserting a third tubular string into the first tubularstring with a second seating nipple disposed in the third tubularstring; connecting the third tubular string to the upper bi-flowconnector; and inserting a second fluid displacement device into thesecond seating nipple.

Another embodiment according to the present disclosure includes anartificial lift system for use in a wellbore extending from a surface toa subterranean reservoir containing reservoir fluids, the systemcomprising: a casing disposed in the wellbore; a first tubular stringdisposed in the casing; an upper bi-flow connector disposed in the firsttubular string, a lower bi-flow connector disposed in the first tubularstring below the upper bi-flow connector; a second tubular stringdisposed below the lower bi-flow connector and sealingly engaging thelower bi-flow connector, wherein the lower bi-flow connector allows flowbetween the second tubular string and the annulus between the casing andthe first tubular string; a third tubular string disposed in the firsttubular string above the upper bi-flow connector; a first fluiddisplacement device disposed in the third tubular above the upperbi-flow connector, wherein the upper bi-flow connector allows flowbetween an annulus formed by the casing and the first tubular string andthe fluid displacement device; and a second seating nipple disposed inthe third tubular string above the upper bi-flow connector, wherein thefluid displacement device is releasably connected to the second seatingnipple.

Another embodiment according to the present disclosure includes a methodof producing reservoir fluids using the artificial lift system describedabove, the method comprising: injecting a fluid from the surface intothe annulus between the first and third tubing string and the first andsecond tubing string.

Examples of the more important features of the disclosure have beensummarized rather broadly in order that the detailed description thereofthat follows may be better understood and in order that thecontributions they represent to the art may be appreciated. There are,of course, additional features of the disclosure that will be describedhereinafter and which will form the subject of the claims appendedhereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference shouldbe made to the following detailed description of the embodiments, takenin conjunction with the accompanying drawings, in which like elementshave been given like numerals, wherein:

FIG. 1 shows a diagram of an embodiment of the system for the first stepof the two-step artificial lift system with a sucker rod pump accordingto the present disclosure;

FIG. 2A shows a diagram of the system of FIG. 1 with the sucker rod pumpbeing removed as part of the installation of the second step of thetwo-step artificial lift system;

FIG. 2B shows a diagram of the system of FIG. 2A after removal of thesucker rod pump and during installation of a third tubing string;

FIG. 2C shows a diagram of the system of FIG. 2B after installation ofthe third tubing string;

FIG. 2D shows a diagram of the system of FIG. 2C after reinstallation ofa sucker rod pump in the wellbore as the final part of step two of thedisclosure with arrows showing the flow paths of the injection gas andreservoir liquids;

FIG. 3 shows a diagram of FIG. 2D with hydraulic pumping instead of gaslift, illustrating the flow paths of the injected fluids and reservoirfluids;

FIG. 4A shows a 3D view of the upper bi-flow connector for use with thesystem shown in FIGS. 1-3;

FIG. 4B shows a cut away view of the upper bi-flow connector alongsection line 4B-4B of FIG. 4A;

FIG. 4C shows a view of the top and bottom of the upper bi-flowconnector of FIG. 4A;

FIG. 4D shows a 3D view of the lower bi-flow connector for use with thesystem shown in FIGS. 1-2D;

FIG. 4E shows a cut away view of the lower bi-flow connector alongsection line 4D-4D of FIG. 4D;

FIG. 4F is a top view of the lower bi-flow connector of FIG. 4D; and

FIG. 4G is a bottom view of the lower bi-flow connector of FIG. 4D.

The above figures are for illustration purposes only and should not beused in a limiting sense. Such as other fluid displacement systems arecontemplated as well as other configurations.

DETAILED DESCRIPTION OF THE DISCLOSURE

An artificial lift system and method is proposed for lifting liquids,particularly liquid hydrocarbons, for implementation in two steps. Thefirst step allows reservoir fluids to be lifted without fluid injectionand associated fluid injection equipment. The second step allows forreservoir fluids to be lifted with gas injection without a completereworking of the well to remove the equipment from the first step.Additionally, the two-step approach allows the addition of down-holeequipment to provide gas injection for when the well needs additionalenergy to aid in lifting liquids from below the fluid displacementdevice to above the device without having to perform a major workover toremove the existing wellbore equipment. Also, the two-step approachprovides more efficient gas separation in the casing annulus whileproviding a higher capacity fluid displacement device. Additionally,step one of the two-step approach is less complicated and has lessinstallation and operating costs than prior art installations forspecific well conditions, such as when reservoir pressure is sufficientfor reservoir liquids to flow out of the well without gas injection.Finally, the two-step approach has an improved solids separation systemthat uses the momentum of the solids and gravity to separate the solidsfrom the fluid stream.

In the following descriptions, like parts are numbered similarly anddrawings are not drawn to scale throughout the specifications. FIGS. 1,2A-2D, 3, and 4A-4B are illustrated in a vertical wellbore but thedisclosure is also contemplated for installations in deviated andhorizontal wellbores. It is also contemplated that openings describedherein may be of a different form than illustrated such as the shape ofa slot, rectangular, oval, and other shapes, and that the openings maybe single or multiple and aligned vertically, horizontally, askew, orrandomly. Additionally, all tubular strings may be tapered with varyingouter or inner diameters and there may additional tubular annularsealing devices, shear subs and other on-off devices than what isillustrated herein. It is contemplated that there may be other fluiddisplacement devices and associated equipment than those that areillustrated herein. Additionally, there may be one or more casingannular sealing devices or no annular casing sealing devices.

FIG. 1 shows an embodiment of a system for lifting reservoir fluids in awellbore without gas injection, which is the first step of the two-stepinstallation. The first step system includes a sucker rod pump 34installed in a first tubing string 12 in a casing 10 in a wellbore. Anupper bi-flow connector 14 and a lower bi-flow connector 16 are disposedin the first tubing string 12. The first step system may include anoptional packer 18. On bottom of the upper bi-flow connector is anoptional mud anchor 56. The optional packer 18 may be disposed betweenthe casing 10 and the first tubing string 12 below the lower bi-flowconnector 18 as well as an optional one way check sub 19 on bottom. Asecond tubing string 20 may be disposed inside the first tubing string12 below the lower bi-flow connector 16. The second tubing string 20 maybe attached to the lower bi-flow connector 16 so that reservoir fluids26 moving up the second tubing string 20 flow into an inner bore 112 ofthe lower bi-flow connector 16 (see FIG. 4E), through one or morechannel(s) 100 and outside the first tubing string 12 into an annulus 28formed by the first tubing string 12 and the casing 10. An optionallower shroud 30 may be disposed around the lateral openings 100 (seeFIG. 4D) of the lower bi-flow connector and configured to direct thereservoir fluids 26 downward in the annulus 28.

An optional upper shroud 32 may be disposed in the annulus 28 around theupper bi-flow connector 14. The upper shroud 32 may be configured tocapture liquids 24 that fall out of the reservoir fluids 26 that aremoving up the annulus 28. The upper bi-flow connector 14 directs theliquids 24 towards the sucker rod pump 34 disposed in the first tubingstring 12 above the upper bi-flow connector 14. Rods are connected tothe sucker rod pump 34 which contain seals 44 and may be disposed inseating nipple 36 within the first tubing string 12. On bottom of thesucker rod pump 34 is spacer 78 containing seals 46 which are sealinglyengaged in seal bore 70. J latch 54 is above seal bore 70 and is notused in the first step system. It is contemplated that anotherartificial lift device may be used in place of the sucker rod pump 34and rods 58.

In operation, the first step system provides for reservoir fluids 26 totravel up the second tubing string 20, which serves as a velocitystring. These fluids 26 exit into the casing annulus 28 throughchannel(s) 100 of the lower bi-flow connector 16. The optional lowershroud 30 is incorporated around the lower bi-flow connector 16 to forcethe fluids 26 in a downward direction which utilizes the momentum of thesolids in addition to gravity to separate the solids from the reservoirfluids 26. Once in the casing annulus 28, the optional packer 18 mayprevent the movement of the first tubing string 12 and prevent reservoirfluids 26 from falling back down the wellbore, therefore the reservoirfluids 26 flow above the upper bi-flow connector 14. Gas 22 separatesfrom the fluids 26 and travels to the surface. Liquids 24 fall and enterthrough channels 100 of the upper bi-flow connector 14, through centerbore 112 (see FIG. 4A), up spacer 78 and then enter the sucker rod pump34 where they are pumped to the surface up the first tubing string 12.Debris that enters bi-flow connector 14 and spacer 78 falls and collectsinto mud anchor 56.

In one embodiment, the first tubing string 12 has a 2.441-inch innerdiameter and can house a larger fluid displacement device 34 and theassociated equipment than prior art designs while also providing a muchlarger cross-sectional area in the casing annulus 28 for more efficientgas 22 separation, reduced back pressure on the reservoir, and higherproduction rates.

FIGS. 2A-2D show the transition from the first step system to the secondstep system. The second step system involves gas 22 injection from thesurface to assist in lifting the reservoir fluids 26 from below a secondfluid displacement device 40 to the surface. The installation of thetwo-step process is very cost efficient in that only the fluiddisplacement device 34 and its associated equipment needs to be removedfrom the wellbore. Once this is accomplished, a third tubing string 42is installed inside the first tubing string 12 and is sealingly engagedto the upper bi-flow connector 14. An additional wellhead (not shown) isinstalled to support the third tubing string 42 and once the secondfluid displacement device 40 is installed, gas 38 is injected into theannulus 28 between the first 12 and third tubing string 42. The abilityto leave the first step system equipment in the well without disturbingor removing it is very valuable because of the inherent risks inremoving equipment from a wellbore and the associated cost savings. Allthe first step equipment is necessary for a second step installation,except for the second fluid displacement device 42, which may be thesame or a similar sized device as the first fluid displacement device 34or it may be replaced with a smaller sized or a dissimilar fluiddisplacement device configured to fit in a smaller tubing string.

FIG. 2A shows the removal of the sucker rod pump 34 and its associatedequipment (seals 44 & 46, spacer 78, rods 58, etc.). FIG. 2B shows theinstallation of a third tubing string 42 containing spacer 78, on-offlugs 62, and seals 46 which are all installed in the first tubing string12. The third tubing string 42 is disposed above the upper bi-flowconnector 14 and includes a seating nipple 60 configured to receive asecond fluid displacement device 40. FIG. 2C shows the third tubingstring 42 in position within the first tubing string 12 with seals 46engaged in seal bore 70 and on-off lugs 62 engaged in j latch 54 toprevent movement of the second fluid displacement device 40 duringpumping operations. FIG. 2D shows the pathway of the various fluidsduring the operation of the second fluid displacement 40 device. Theannulus 48 between the third tubing string 42 and the first tubingstring 12 forms a path for injected gas 38 to flow downward intochannels 102 of the upper bi-flow connector 14 and further downwardthrough channels 102 of the lower bi-flow connector 16 and into theannulus 76 between the second tubing string 20 and the first tubingstring 12.

In operations, the second step system injects gas 38 into the well fromthe surface and travels down the annulus 38 between the first 12 andthird tubing string 42. The injection gas 38 passes through channels 102of the upper bi-flow connector 14 and through the 102 of the lowerbi-flow connector through the annulus 76 between first tubing 12 andsecond tubing 20. The gas 38 then enters the second tubing string 12 andcommingles with reservoir fluids 26 to become commingled fluids 25 whichflow up the second tubing string 20 and then exits into the casingannulus 28 through channels 100 of the lower bi-flow connector 16. Theoptional shroud 30 forces the lifted commingled fluids 25 in a downwarddirection and the momentum of the solids along with gravity separate thesolids from the fluids 25. The fluids 25 are prevented from falling backdown the wellbore by the packer 18. Gas 22 separates from the fluids 25and travels to the surface while the liquids 24 fall and enter throughthe channels 100 of the upper bi-flow connector 14 and enter the secondfluid displacement device 40 where the liquids 24 are pumped to thesurface up the third tubing string 42.

FIG. 3 shows another embodiment of the second step system where ahydraulic pump 50 is used instead of gas injection 38 to lift thereservoir fluids 26. The hydraulic pump 50 is disposed in the secondtubing string 20 below the lower bi-flow connector 16. If an optionalpacker 18 is present, the hydraulic pump 50 is disposed below theoptional packer 18. The hydraulic pump 50 may be seated in a seatingnipple 75 disposed in the second tubing string 20 that contains seals 23to seat in a seating nipple 21. A one-way check sub 19 is installedbelow the seating nipple 21. It is also contemplated to allow thehydraulic pump 50 to be removed and re-installed from the wellbore via awireline unit for purposes of repair or replacement. This may beaccomplished by also removing plug 66 from the seating nipple 72 in mudanchor 56, and removing plug 68 from seal bore 74 with-in the lowerbi-flow connector 16. It is also contemplated that the seal bore 74 beconnected above and not a part of bi-flow connector 16. In thatinstance, bi-flow connector 16 would be essentially the same as bi-flowconnector 14. The operations of FIG. 3 are the same as FIG. 2D.

A major benefit of the first step system is that a major workover is notrequired when converting to a second step system, unlike prior artsystems. Additionally, the optional shroud 30 incorporated to surroundthe lower bi-flow connector 16 using the momentum of the solids andgravity provides improved solids separation.

FIG. 4A shows an upper bi-flow connector 14 which includes a body 111with an upper end 105 and a lower end 107 with one or more lengthwisechannels 102 through a thickness of body 111 from the upper end 105 tothe lower end 107. The body 111 also has an inner bore 112 running fromthe upper end 105 to the lower end 107. Inner bore 112 contain internalthreads 106 on end 105 and internal threads 110 on end 107 (see FIG.4B-4C) that allows a tubular to be connected to inner bore 112 on end105 and 107. As shown the inner bore 112 is circular and in the centerof the body 111; however, other embodiments are contemplated where theinner bore 112 is offset from the center and/or is not circular inshape. One or more side channels 100 run through the thickness and intothe inner bore 112. Channels 100 and 102 do not intersect. End 105 maycontain external threads 104 and end 107 may contain external threads108 that allow the bi-flow connector 14 to be connected to a tubingstring.

FIG. 4B shows a cut away view of bi-flow connector 14 along lines 4B-4Bof FIG. 4A with end 105 and 107, center bore 112, external threads 104and internal threads 106 on end 105 and external threads 108 andinternal threads 110 on end 107.

FIG. 4C shows a view of end 105 or 107 of bi-flow connector 14 with athickness 109, channels 102, center bore 112, and internal threads 106or 110.

FIG. 4D shows a lower bi-flow connector 16 like the upper bi-flowconnector 14 except the inner bore 112 on end 105 is plugged and doesnot contain internal threads 106.

FIG. 4E shows a cut away view of bi-flow connector 16 along lines 4E-4Eof FIG. 4D with end 105 and 107, center bore 112, external threads 104on end 105 and external threads 108 and internal threads 110 on end 107.

FIG. 4F shows a top view of end 105 of bi-flow connector 16 withchannels 102 and body 111.

FIG. 4G shows a bottom view of end 107 of bi-flow connector 16 showing athickness 109, body 111, channels 102, and internal threads 110.

While the disclosure has been described with reference to exemplaryembodiments, it will be understood that various changes may be made andequivalents may be substituted for elements thereof without departingfrom the scope of the disclosure. In addition, many modifications willbe appreciated to adapt a particular instrument, situation or materialto the teachings of the disclosure without departing from the essentialscope thereof. Therefore, it is intended that the disclosure not belimited to the particular embodiment disclosed as the best modecontemplated for carrying out this disclosure, but that the disclosurewill include all embodiments falling within the scope of the appendedclaims.

What is claimed is:
 1. An artificial lift system for use in a wellboreextending from a surface to a subterranean reservoir containingreservoir fluids, the system comprising: a casing disposed in thewellbore; a first tubular string disposed in the casing; an upperbi-flow connector disposed in the first tubular string, a lower bi-flowconnector disposed in the first tubular string below the upper bi-flowconnector; a second tubular string disposed below the lower bi-flowconnector and sealingly engaging the lower bi-flow connector, whereinthe lower bi-flow connector allows flow between the second tubularstring and the annulus between the casing and the first tubular string;a first fluid displacement device disposed in the first tubular abovethe upper bi-flow connector, wherein the upper bi-flow connector allowsflow between an annulus formed by the casing and the first tubularstring and the fluid displacement device; and a first seating nippledisposed in the first tubular string above the upper bi-flow connector,wherein the fluid displacement device is releaseably connected to thefirst seating nipple.
 2. The artificial lift system of claim 1, whereinsaid upper bi-flow connector comprises a tubular that contains a centerbore in communication with one or more horizontal channel(s) that extendthrough the width of the device, and one or more vertical channel(s)that extend through the length of the device, and said horizontalchannel(s) and said vertical channel(s) do not communicate with-in saidbi-flow tool
 3. The artificial lift system of claim 2, wherein saidcenter bore extends to the upper end of said upper bi-flow connector butdoes not extend to the lower end of said upper bi-flow connector
 4. Theartificial lift system of claim 2, wherein said center bore extends tothe upper and lower end of said upper bi-flow connector
 5. Theartificial lift system of claim 1, wherein said lower bi-flow connectorcomprises a tubular that contains a center bore in communication withone or more horizontal channel(s) that extend through the width of thedevice, and one or more vertical channel(s) that extend through thelength of the device, and said horizontal channel(s) and said verticalchannel(s) do not communicate with-in said bi-flow tool and said centerbore extends to the lower end of said tubular but does not extend to theupper end of said tubular
 6. The artificial lift system of claim 1,further including one or more casing annular sealing device or devicesinstalled in said first tubing string below said lower bi-flow connector7. The artificial lift system of claim 6, further including a one-waycheck sub installed in said first tubing string below said casingannular sealing device(s)
 8. The artificial lift system of claim 1,further including an upper shroud surrounding said upper bi-flowconnector and a lower shroud surrounding said lower bi-flow connector 9.A method of modifying the artificial lift system of claim 1, the methodcomprising: removing the first fluid displacement device from thereleaseably connected first sealing nipple; inserting a third tubularstring into the first tubular string with a second sealing nippledisposed in the third tubular string; connecting the third tubularstring to the upper bi-flow connector; and inserting a second fluiddisplacement device into the second sealing nipple
 10. An artificiallift system for use in a wellbore extending from a surface to asubterranean reservoir containing reservoir fluids, the systemcomprising: a casing disposed in the wellbore; a first tubular stringdisposed in the casing; an upper bi-flow connector disposed in the firsttubular string, a lower bi-flow connector disposed in the first tubularstring below the upper bi-flow connector; a second tubular stringdisposed below the lower bi-flow connector and sealingly engaging thelower bi-flow connector, wherein the lower bi-flow connector allows flowbetween the second tubular string and the annulus between the casing andthe first tubular string; a third tubular string disposed in the firsttubular string above the upper bi-flow connector; a first fluiddisplacement device disposed in the third tubular above the upperbi-flow connector, wherein the upper bi-flow connector allows flowbetween an annulus formed by the casing and the first tubular string andthe fluid displacement device; and a second seating nipple disposed inthe third tubular string above the upper bi-flow connector, wherein thefluid displacement device is releaseably connected to the second seatingnipple
 11. The artificial lift system of claim 10, wherein said upperbi-flow connector comprises a tubular that contains a center bore incommunication with one or more horizontal channel(s) that extend throughthe width of the device, and one or more vertical channel(s) that extendthrough the length of the device, and said horizontal channel(s) andsaid vertical channel(s) do not communicate with-in said bi-flow tool12. The artificial lift system of claim 10, wherein said center boreextends to the upper end of said upper bi-flow connector but does notextend to the lower end of said upper bi-flow connector
 13. Theartificial lift system of claim 10, wherein said center bore extends tothe upper and lower end of said upper bi-flow connector
 14. Theartificial lift system of claim 10, wherein said lower bi-flow connectorcomprises a tubular that contains a center bore in communication withone or more horizontal channel(s) that extend through the width of thedevice, and one or more vertical channel(s) that extend through thelength of the device, and said horizontal channel(s) and said verticalchannel(s) do not communicate with-in said bi-flow tool and said centerbore extends to the lower end of said tubular but does not extend to theupper end of said tubular
 15. The artificial lift system of claim 10,further including one or more casing annular sealing device or devicesinstalled in said first tubing string below said lower bi-flow connector16. The artificial lift system of claim 15, further including a one-waycheck sub installed in said first tubing below said casing annularsealing device(s)
 17. The artificial lift system of claim 10, furtherincluding a third fluid displacement device installed in the secondtubular string
 18. The artificial lift system of claim 17, furtherincluding one or more removeable plugs located in or between said upperand lower bi-flow connectors to allow said third fluid displacementdevice to be retrieved without having to remove wellbore tubulars 19.The artificial lift system of claim 10, further including an uppershroud surrounding said upper bi-flow connector and a lower shroudsurrounding said lower bi-flow connector
 20. A method of producingreservoir fluids using the artificial lift system of claim 10, themethod comprising: injecting a fluid from the surface into the annulusbetween the first and third tubing string and the first and secondtubing string.